Many reservoirs from which oil and gas are produced are not homogeneous in the geologic properties (e.g. porosity and permeability). In fact, many of such reservoirs, especially those consisting of carbonate type of rocks (e.g. limestone and dolomite) are naturally and significantly fractured. Typical examples of such reservoirs are those in the Spraberry trend in West Texas. In addition, often in carbonate reservoirs the rock matrix is fractured deliberately by well treatments in order to increase the flow of fluids near the well bore region.
Fractured reservoirs consist of two distinct elements: fractures and matrix. The fracture system is a series of interconnected cracks that can transmit fluids easily (very high permeability), but make up only a small fraction of the total porosity. The matrix portion consists of the oil-bearing porous rock that typically has much lower permeability and has the bulk of the total porosity of the reservoir. Hydrocarbon production is normally less efficient in fractured reservoirs. During primary production the natural reservoir pressures to produce the oil in place will quickly decrease and more than 90% of the original oil in still left in place. Similarly, conventional methods of secondary recovery fail to displace substantial volumes of “left-in-place” oil.
Conventional waterflooding techniques have relatively low efficiency in highly fractured reservoirs. Waterflooding in these reservoirs is characterized by early water breakthrough and rapidly increasing water-oil ratios to an uneconomic level. The injected water tends to travel only through the fractures and not interact with the rock matrix. That is, the water cannot penetrate into the matrix and thereby displace and recover oil trapped in the porous matrix. This injected water tends to recover only the oil left behind in the fracture system following primary production. This limited or no interaction of the water with the matrix is caused in large part by the matrix portion not being water-wet. That is, the matrix will not spontaneously imbibe water.
One approach to increase the penetration of a water phase with the matrix blocks containing trapped oil is to add a surfactant to the water. Previous research and field experience has demonstrated that including a low concentration of the properly selected surfactant to the water will reduce the interfacial tension and also create now a water-wet condition in the area near the fracture face. With this altered condition, the aqueous phase then penetrates some distance into the porous matrix and thereby pushes out some of the oil that was within the pore spaces. In this countercurrent imbibition process the oil that is displaced from the matrix then moves into the fracture system. Once pushed into the fracture system, this oil can be moved easily to a production well. In a countercurrent imbibition process, with or without the addition of a water-wetting surfactant, the rate of oil recovery is dependent upon the capillary pressure characteristics of the porous rock matrix. That is, the imbibition process is essentially unaffected by conventional techniques for controlling field operations, such as selecting pressures and flow rates.
“Surface Chemistry of Oil Recovery from Fractured, Oil-Wet Carbonate Formations” (G. Hirasaki and D. L. Zhang, (2000)) describes an oil recovery process employing water-imbibition displacement in naturally fractured carbonate reservoirs. U.S. Pat. No. 4,364,431 to Saidi et al utilizes a surfactant to augment a waterflood which displaces oil from a fractured formation, by a gravity drive mechanism rather than an imbibition displaced mechanism. Saidi suggests that the surfactant reduces the interfacial tension between the water in the factures and the oil in the matrix blocks of the formation, which enables the oil to enter the factures where it is driven upward to a producing well by the density difference between water and oil.
Waterflood recovery by countercurrent imbibition may be further improved by the use of surface active agents which reduce interfacial surface tension between the oil and water phase, as disclosed in U.S. Pat. No. 2,792,894 by Graham. Examples included the improved imbibition into a porous rock by an aqueous phase that includes a surfactant. This process is advantageous for fractured reservoirs where there is a marked capillary pressure difference between the fluids in the fracture system and the porous rock formation.
U.S. Pat. No. 4,842,065 by McClure discloses that alternating surfactant slugs and water can improve oil recovery in fractured formations. The surfactant solution causes it to be the preferred wetting phase of the matrix blocks into the fracture network. The formation is then flooded with water from an injection well to displace the oil from the fracture network to the surface via a production well while returning the matrix blocks in the reservoir to a less water-wet condition. The injection cycle is repeated until the formation is depleted.
Austad and Standes in “Spontaneous Imbibition of Water into Oil-Wet Carbonates”, Journal of Petroleum Science and Engineering, 2003, vol 39, pp. 363-376, describes laboratory experiments in which aqueous surfactant solutions recover oil from carbonate cores. These authors present data for a number of cationic and anionic surfactants, that when dissolved as a dilute solution in water, will imbibe spontaneously into carbonate cores containing a crude oil, and thereby recover some of this crude oil. H L Chen et al. present in paper SPE 59006 results for similar laboratory experiments in which aqueous solutions of nonionic surfactants imbibe into and thereby recover from carbonate cores oil formerly trapped inside the porous core. Hirasaki and Zhang demonstrate that anionic surfactants in an aqueous solution also containing sodium carbonate to increase the solution pH and adjust the salinity can imbibe into carbonate cores that contain initially a high saturation of a crude oil.
One method in particular to apply aqueous surfactant solutions to increase the oil recovery from fractured reservoirs is to treat individual production wells with a stimulation fluid that comprises a fresh water or brine with a suitable surfactant added. A “suitable surfactant” is a surfactant that will dissolve in the injection brine, be compatible with the reservoir brine, plus its solution has the desired behavior to penetrate spontaneously into a porous matrix. The injection-production method described below may be called a “huff-puff”, “surfactant soak”, or “surfactant squeeze” treatment. First, a production well halts production of fluids. Next a brine/surfactant solution is injected into the production well. This forces the treatment fluid into the fracture system some distance from the wellbore and into the reservoir. This is followed by an optional flush fluid to drive the surfactant deeper into the reservoir. The well may be shut-in for a period of time (typically from a few hours to a few days) to allow the surfactant solution to soak better into the matrix and displace some of the trapped oil in the matrix into the fracture system. Finally, the well is placed back on production and the extra oil forced into the fractures comes back to the production well and is produced. This process can increase the oil production for some period of time when the well is placed back on production. This oilfield application method is described, and is observed to recover additional oil, for example, in the HL Chen paper SPE (Society of Petroleum Engineers) 59006 and the paper by W. W. Weiss (“Artificial Intelligence Used to Evaluate 23 Single-Well Surfactant Soak Treatments”, SPE Reservoir Evaluation & Engineering, June 2006).
The June 2006 paper by Weiss includes a discussion about the surfactant oil recovery results being worse than expected when there is an acid treatment that is performed before the application of the surfactant. It is speculated that the acid reacting first on the rock surfaces impedes the penetration of the surfactant that contacts those same acid-treated surfaces later. Thus combined application of the surfactant soak and a second process can produce a negative result. (It is noted that the June 2006 paper by Weiss et al. is dated after the priority date of this application, and so does not constitute “background” art, but is merely included to demonstrate an important point, and that is that other well treatments, when followed by a surfactant injection, can produce negative results over surfactant treatment alone.)
U.S. Pat. No. 5,247,993 to Sarem et al. describes an improvement wherein, if while performing a surfactant soak process in a fractured reservoir, that the fluid in the flush step (i.e., the fluid just after the surfactant slug) can increase the oil-mobility and decrease the water-mobility. Examples cited therein include using steam or hydrocarbon, or adding a thickening agent to the water flush.
A need therefore exists for processes that improve on the oil production and economic results of surfactant solution injection-production processes in oil reservoirs.